The present disclosure relates generally to a downhole oscillation apparatus. More particularly, but not exclusively, the present disclosure pertains to a drilling apparatus and a drilling method, and to a flow pulsing method and a flow pulsing apparatus for a drill string.
In the oil and gas exploration and extraction industries, forming a wellbore conventionally involves using a drill string to bore a hole into a subsurface formation or substrate. The drill string, which generally includes a drill bit attached at a lower end of tubular members, such as drill collars, drill pipe, and optionally drilling motors and other downhole drilling tools, can extend thousands of feet or meters from the surface to the bottom of the well where the drill bit rotates to penetrate the subsurface formation. Directional wells can include vertical or near-vertical sections that extend from the surface as well as horizontal or near horizontal sections that kick off from the near vertical sections. Friction between the wellbore and the drill string, particularly near the kick off point and in the near horizontal sections of the well can reduce the axial force that the drill string applies on the bit, sometimes referred to as weight on bit. The weight on bit can be an important factor in determining the rate at which the drill bit penetrates the underground formation.
Producing oscillations or vibrations to excite the drill string can be used to reduce the friction between the drill string and the wellbore. Axial oscillations can also provide a percussive or hammer effect which can increase the drilling rate that is achievable when drilling bores through hard rock. In such drilling operations, drilling fluid, or mud, is pumped from the surface through the drill string to exit from nozzles provided on the drill bit. The flow of fluid from the nozzles assists in dislodging and clearing material from the cutting face and serves to carry the dislodged material through the drilled bore to the surface.
However, the oscillations produced by known systems can be insufficient in reducing friction in some sections of the drill string and can cause problems if applied in other sections of the drill string. Friction in the vertical sections of the well bore is generally not as great as at the kick-off point and in the near-horizontal sections. With little attenuation produced by friction, oscillations produced in the near vertical sections of the drill string and wellbore can damage or create problems for drill rig and other surface equipment. Moreover, oscillations can coincide with harmonic frequencies of the drill string (which can depend on the structure and makeup of the drill string) and constructively interfere to produce damaging harmonics.
Also, the near horizontal sections of a directional well can be very long and, in some cases, significantly longer than the vertical sections. As the drill string penetrates further in the horizontal portions of the well, exciter tools in the drill string can move further away from the high friction zones of the wellbore at the kick-off point and nearby horizontal sections. The high friction in the horizontal sections can attenuate the oscillations produced by distant exciter tools.
With the recent dramatic increase in unconventional shale drilling, many challenges follow, as these wells typically include extended reach lateral sections. These challenges include, but are not limited to: low rate of penetration (ROP), stick-slip, and poor weight on bit (WOB) transfer along the drill string. There is a strong desire in the market for a drilling tool which can address these challenges. What is needed, therefore, is an improved downhole oscillation apparatus and method.